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Fracking up the country

Hydraulic fracturing has completely altered the US’s energy scene and could soon be coming to a county near you (Lancashire, to be exact). Libby Peakeconsiders the process and the wastes it produces

Opponents of fracking have a very long list of concerns when it comes to the technique: they say that it contributes to climate change and causes air pollution; that it uses unsustainable amounts of water while also contaminating drinking supplies with methane and toxic chemicals; that it wreaks havoc on landscapes and settlements through heavy industrialisation; and that it triggers earthquakes. Those who support the industry tend to dismiss such concerns as misguided or based on myth, with a recent Chatham House briefing on shale gas claiming it’s ‘an area where popular ignorance overrules science’. So, Resource thought it time to take our own look at the matter, with a specific focus on the waste it produces.

But first, a crash course in the technology itself. Though its rise to prominence has happened swiftly over the last few years, hydraulic fracturing (to give it its full name) was actually developed in the 1940s in Texas, and the ideas behind it can be traced to the 1860s, when nitroglycerin ‘shooting’ was used to break rocks to stimulate oil flows in the east of the US. These days, the technique entails water treated with chemicals and sand being injected into wells at high pressure – up to 8,000 pounds per square inch (psi). The pressure induces artificial fractures in the surrounding rock, and the sand props the fissures open, allowing the gas to flow into the well to be collected at the surface. It is often used to liberate natural gas trapped in shale formations, as, because of their high porosity and low permeability, shales are not sources for conventional gas (in other words, shale gas doesn’t accumulate in discrete pools and won’t flow on its own, as in dramatic scenes of ‘striking oil’).

Successful fracking requires the ability not only to drill deep wells, but also to drill horizontally miles below the earth’s surface, and it wasn’t until ‘multi-stage fracking’ hit the scene around 2009 that shale gas became profitable. This innovation allows a company to drill a well horizontally through several thousand metres of shale and frack one section of the formation at a time. Operators send down a perforated pipe gun and fracture the immediately surrounding rocks, before plugging off each already-fracked section and moving on down the line. The technique allows a company to drill only one well where it would have needed 10 to 12 in the past.

The so-called ‘shale gas revolution’ has completely altered the energy scene in the US; between 2000 and 2010, shale gas increased from less than one per cent of America’s domestic gas production to more than 20 per cent. The figure is expected to rise to 46 per cent by 2035, potentially allowing the US to become self-sufficient in terms of energy that same year (it is expected to surpass Russia and Saudi Arabia as the world’s largest oil producer in 2017). The boom has also seen natural gas prices in the US drop dramatically, to around a fifth of the price per unit in Europe and Japan.

Needless to say, the rest of the world has taken notice, and many countries are now attempting to replicate the ‘successes’ of the US. Though reserves of shale gas are notoriously difficult to estimate accurately (Poland, for instance, originally estimated it had reserves totalling 5,300 billion cubic metres (bcm), but later reduced the figure to just 346-768 bcm), there are several large shale gas basins in Europe. Substantial reserves are predicted to be running under Slovakia, Hungary, Romania and Bulgaria, as well as in Germany and France, though France and Bulgaria have both banned the technique outright. The UK has both a government that strongly supports fracking, as well some potential reserves – the largest being the Bowland Shale in Lancashire, the only formation in the country that has so far seen any form of exploration.

But Tony Bosworth, Friends of the Earth’s Senior Energy Campaigner, tells me it would be naïve to expect a repeat of the US’s successes here: “What happened in the US cannot be replicated in the UK and Europe. The conditions are different and the population density is so much higher, and there are tighter regulations.” Indeed, the aforementioned Chatham House briefing highlights conditions that ‘could inhibit replication’, including differing property rights (which reside with the landowner in the US and the state in Europe), higher costs of drilling, less infrastructure and poorer geological conditions: ‘Shale plays are smaller, deeper, [contain] less material and [have] a high clay content, making fracking more difficult’, the report reads.

And classifying what’s happening in the US as a ‘success’ is a bit naïve, too; Bosworth concludes: “We can also learn from the US experience that there have been problems. There are problems with air pollution, with contamination of water, with the existing energy mix. We need to look at those and learn the lessons before we decide whether we want to push ahead in the UK.”

These ‘problems’ include potential links to earthquakes (admittedly measly tremors of 1.5 and 2.3 in Lancashire were linked to shale gas exploration in 2011 and led to a temporary suspension of drilling), as well as links to climate change. Shale gas is being promoted in the UK as a ‘transition fuel’ to be used until renewables take off, but as the Chatham House briefing puts it, there are growing concerns that ‘gas could well end up substituting not for (cheap) coal but for (relatively expensive) renewables’. What’s more, some studies suggest shale gas can actually be ‘dirtier’ than coal over the course of its lifecycle, and as Bosworth points out: “At the global level, there are known resources of conventional gas equivalent to 120 years of current consumption. If we want to tackle climate change, we can’t afford to even burn a small percentage of that, so there’s little point in trying to find more fossil fuels.”

And then of course, there’s the waste that results from the process, which comes in all the different phases of matter: liquid, gas and solid. Let’s start with liquid, by far the largest concern given the volume of water required and the substances potentially added to it. Bosworth explains: “In a typical shale gas well, you use maybe four million gallons of water to frack it, and within that, there’s a small percentage of chemicals, but that still amounts to 20,000 gallons of chemicals going down. Of that four million gallons of water, unhelpfully it can be between 20 and 80 per cent staying down and between 20 and 80 per cent coming back up again. If you take the halfway point and assume that half comes up again, you have two million gallons to deal with.”

Marcelius Shale gas drilling tower. Source: Ruhrfisch

As Bosworth points out, the water that goes down is combined with a very small proportion of chemicals. In the US, until the passing of the Fracturing Responsibility and Awareness of Chemicals (or FRAC) Act in 2011, fracking was basically entirely unregulated and companies were able to maintain as trade secrets the chemicals they added to the water. Campaigners claimed there were more than 600 different chemicals in fracking fluid, though, with a number of known carcinogens and teratogens (substances that cause birth defects) among them.

In the UK, companies will be required to divulge the substances they add to the fluid, and Cuadrilla, the only company to have carried out any exploratory drilling to date, claims to add only one chemical to its fracking fluid. A spokesperson for the company told Resource: “Mains water and sand make up 99.95 per cent of Cuadrilla’s fracturing fluid. Around 0.04 per cent of the fracturing fluid is a friction reducer called polyacrylamide, which is commonly used in facial cream and contract [sic] lenses. This is added to the water to minimise pressure loss due to friction with the pipe as the water flows the one mile or greater distance from the surface to the shale rock far below.”

Confused as to how Cuadrilla could use so few chemicals compared to operators in the US, I sought the opinion of Mike Hill, a former oil and gas man who has provided technical advice on fracking to Lancashire’s Fylde Borough Council. He explains: “It depends on the shales themselves and how much gas they give back and over what time period. With unconventional gas, it’s very hard to get the hydrocarbons to flow because they’re trapped in the shale. Now, over the period of a year, it’s very common for a shale gas well to drop off its production by over 70 per cent. So to increase the flow rate, and to try to maintain the tiny pores that allow the gas to flow, the shale gas companies put in more and more chemicals. So, initially, Cuadrilla can claim they’re only using three [hydrochloric acid, biocide and the aforementioned polyacrylamide] because we’re in the exploration phase, and when they move to production, then it’ll change.”

It’s not just the chemicals that are added to fracturing fluid that we have to consider, but also the substances the water picks up when it’s deep underground, at high pressures and temperatures. An Environment Agency (EA) document monitoring Cuadrilla’s flowback water explains: ‘There are notably high levels of sodium, chloride, bromide and iron, as well as higher values of lead, magnesium and zinc compared with the local mains water that is used for injecting into the shale.’ Hill puts those figures into context: “Compared with drinking water it had something like 1,400-odd times the lead. It had cadmium, chromium, arsenic at 50 times drinking water; I think chromium was 636 times drinking water. It had...radium 226 at 90 times the EA’s [radioactive threshold level] of one Becquerel per litre.”

Most worrying, perhaps, are these radioactive materials. A spokesperson for the EA explains: “Naturally occurring radioactive materials (NORM) are present in many geological formations including oil and gas bearing strata such as shale formations. The flowback fluid that returns to the surface following hydraulic fracturing, as well as sediments and scales in gas or water process vessels, are likely to contain sufficient NORM that they will be classed as radioactive waste.”

Cuadrilla’s initial radioactive wastewater from test wells was treated by United Utilities at its Davyhulme treatment works before it was discharged into the Manchester ship canal. Again, Hill offers a bit of perspective: “The radiation, by the way, you can’t treat. So they tend to treat it by diluting it. But there’s a problem by diluting it because each well pad that Cuadrilla will drill is going to produce around 25 million gallons of flowback. And if you consider that there are going to be around 300 well pads, you’re looking at about 2.5 billion gallons of water that they’ve got to treat. And so if you were to dilute that, you would need an additional 180 billion gallons of water.”

Though Cuadrilla’s drilling is again suspended for the time being, if it resumes, a new company, Remsol, will be handling its wastewater. Remsol has been working with Cuadrilla to develop what it believes is a ‘safe and sustainable way of managing the wastewaters generated in the hydraulic fracturing process’. Both Cuadrilla and the Environment Agency assured me that the water would be treated at licensed wastewater treatment plants, but did not go into detail about how the radiation, and indeed other chemicals, would be removed. Lee Petts, Managing Director of Remsol, has explained, however, that the treatment process will take advantage of the fact that radionuclides of the type that are found in returned fracking waters are chemically attracted to calcium and can be absorbed by iron hydroxide. The process is similar to one used in the nuclear industry to remove artificially-produced radionuclides, and in plant-scale trials, Petts says, the acid/alkali process succeded in removing 90 per cent or more of radium 226.

Spent shale. Source: Argonne National Laboratory

In the US, things are rather different, so it would be difficult to learn from the country’s experience with fracking wastewater treatment. Bosworth explains: “Cuadrilla have only test fracked one well – we don’t yet know fully how the wastewater would be treated. In the US, it’s less of a problem because what they tend to do is just reinject the wastewater underground, but that is something which is not allowed in the EU, and anyway that’s not something we would necessarily want to do because there’s a lot of evidence that reinjecting wastewater underground can trigger earthquakes.” In addition to deep-well injection, some US operators treat wastewater by leaving it in open-air pits to evaporate, which campaigners complain leads to volatile organic chemicals (VOCs) being released, acid rain and groundwater ozone. Some states (with mind-boggling disregard for environmental protection) also spray the water onto roads as a deicer, and some have also considered solidifying the waste to put it into landfills.

Reusing some of the returned waters is also common in fracking operations, though it can’t always be recycled – especially when mineral content is high. The Cuadrilla spokesperson tells me that this is one US practice the company would look to implement here: “Recycling flowback water between multiple wells on a single resource hub is the most sustainable method of managing water use in hydraulic fracturing operations under field development, greatly reducing water usage and road traffic associated with the transport of water.”

Perhaps of most concern, though, is the water that doesn’t return to the surface, as there’s obviously no way to treat that. Operators claim that there’s no way it can enter underground aquifers, but others aren’t so sure. Hill explains: “Around about two million gallons, two point five million gallons per well never flows back up again. So that water just percolates through the rock formation and they don’t know where it goes. And that’s the water that over a period of time – 10, 15 years – could find its way up to the aquifer. And if it does, it would then find its way into crops and into the food chain.” Though he’s adamant that proper well construction (coupled with proper regulation) could prevent this from happening, he warns that if aquifers do become contaminated, it could devastate agriculture by requiring crops from the area to be banned for many years, adding: “It’ll make BSE and the horse meat scandal look like nursery exercises.”

In addition to the liquid wastes, there are also solid and gaseous wastes, though these tend to be less controversial. Drill cuttings are rock and oil carried to the surface during drilling operations, for instance, and drilling muds are fluids used to aid the drilling process by lubricating and cooling the drill bit. In its waste management plan, Cuadrilla claims each well will produce approximately 300 tonnes of drill cuttings and no more than 3,000 cubic metres of drilling mud. It also claims that these wastes should be classified as non-hazardous, a claim Hill questions: “They’re saying the drilling wastes are just saline and therefore non-hazardous, and to be honest, I don’t believe it. When I was drilling – I was a well engineer – we were using mercury, we were using lead and all sorts of stuff to enable us to drill through rocks and cool the drill bit.”

Hill seems most concerned that the regulations around shale gas are so lacking in the UK, repeatedly telling me that no one is checking that Cuadrilla is doing as it claims. Further, he says that the authorities are relying on self regulation and outdated offshore drilling regulations that are inappropriate for drilling on land and, in the case of Lancashire, very close to centres of population. A series of letters between Hill and government officials including MP Tim Yeo and the Health and Safety Executive and published by the Guardian shows that an inspection regime is disturbingly lacking and that ‘unconventional’ gas is governed by no specific regulations.

The exchange also shows that the government has not conducted any analysis into fracking’s impact on climate change and renewable energy, which is where the gaseous waste comes into it. ‘Fugitive emissions’ happen in all forms of gas extraction and are basically leakages, in shale gas’s case of methane (25 times more powerful than carbon dioxide). The most common way to handle them is to burn off – or flare – the gas before it fully escapes to turn it into less potent carbon dioxide, though this, of course, still represents a waste. Estimates vary greatly as to how many fugitive emissions escape, though a (much criticised) Cornell University study said because of leakages, the footprint of shale gas is at least 20 per cent greater than that of coal. Hill tells me it’s possible to eliminate leakages and flaring, but it is very expensive and, again, would require appropriate regulations.

Several times during our interview, Hill calls himself ‘an engineer, not a green’, and given his concern with regulation, I ask if he thinks the industry could be properly regulated. “Yes, it could”, he responds. “Nothing is 100 per cent safe, but I believe as an engineer that if you thoroughly and independently regulated it – bringing in random, frequent inspections – then you could ensure it was safe.” I ask the green Tony Bosworth the same question, and his reply is predictably different: “I think you can regulate the industry and make it safer, but you can’t make it safe. There are a huge amounts of unknowns in place... and because we have the potential for green energy, it’s a risk we simply don’t need to take in the UK.”

Whether you’re a green or an engineer, though, there certainly seem to be reasons for concern.

This article has been modified from the print version to correct certain factual inaccuracies.

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